Hydraulic Fracturing Method

ABSTRACT

A method is given for diverting injected slickwater in a hydraulic fracturing treatment. The diversion fluid is preferably a substantially proppant free viscous fluid that causes a net pressure increase and plugging of some of the microfractures in the initial fracture system created, which induces formation of supplementary microfractures connected to the initial fracture network and in-creases the contact area with the formation rock. The method generates a greater fracture network complexity and thus a higher contact area with the reservoir during a single treatment cycle.

BACKGROUND OF THE INVENTION

Recovery of hydrocarbons from unconventional reservoirs, for example tight sandstones and shales, usually requires stimulation, for example hydraulic fracturing, to achieve economic production. Water or slickwater (so-called when water with a small amount of a friction reducer is used) are often used as fracturing fluids for stimulation of low permeability unconventional reservoirs. Such treatments are designed to stimulate large reservoir volumes and to open more surface area of hydrocarbon-retaining rock, thus enhancing production. While slickwater fluids usually provide poor transport for conventional proppants, due to their very low viscosity, they still have been found effective and economic. Using low-viscosity fluids for fracture stimulation in low-permeability reservoirs sometimes results in the creation of a network of intersecting fractures and sometimes results in propagation of a single fracture plane. Although the low conductivity achieved with these treatments is often adequate in shale formations, it is believed that an increase in the contact area by generation of a complex fracture network is one of the key factors that can enhance hydrocarbon production in such formations.

Existing treatment techniques have not proven to be sufficiently effective for formation of fracture networks with high fracture densities. The fracture network complexity is reflected in the number of interconnected fractures in the fracture network system as shown in FIG. 1. There is a need for a reliable fracture treatment technique that generates a greater fracture network complexity and thus a higher contact area with the reservoir during a single treatment cycle.

SUMMARY OF THE INVENTION

One embodiment of the invention is a method for fracturing a subterranean formation in which a sequence of fluids is injected into the formation; the sequence has as a feature a first cycle that involves (a) injecting a pad fluid having a viscosity of less than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, (b) injecting proppant slurry having a viscosity of less than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, (c) injecting a thickened fluid (that will act as a diverting agent) having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, and one or more than one subsequent cycles incorporating repeating steps (b) and (c). Optionally, a pad fluid is injected first. Typically the permeability of the formation is less than about 1 mD.

In another embodiment, the thickened diverting fluid has a viscosity of less than about 20 mPa·s as pumped and then thickens in the reservoir, for example the reservoir contains carbonate and the thickened fluid is initially acidic and becomes more viscous as acid is consumed. Self-diverting acids systems may be used to form such systems that thicken in the reservoir.

In various other embodiments, the thickened fluid further contains a proppant; the total volume of the fluid injected in steps (b) is at least 75 percent of the total volume of fluid injected in the treatment; and the fluid injected in steps (b) carries at least 90 percent of the total proppant injected in the treatment; the proppant has a shape selected for example from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs, fibers, arches/cells, meshes, meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and mixtures of these shapes; the size of the proppant ranges from about 5 to about 1000 microns.

In yet another embodiment, at least one of the injected fluids comprises solid degradable materials, for example polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of these materials. The degradable materials are typically used in the form of fibers, plates, flakes, beads and combinations thereof.

In further embodiments, the fluid of step (a) or the fluid of step (b) or both contain a friction reducing agent. The fluid of step or steps (c) may optionally contain less than about 0.024 kg proppant per liter of clean fluid or may optionally be substantially proppant free.

In yet further embodiments, one or more than one cycle is followed by injection of a fluid having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions and containing a coarse proppant; the one or more steps of injection of a fluid having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions containing a coarse proppant may optionally be followed by injection of a fluid containing a proppant flowback control agent.

In another embodiment, the method includes a final step of injecting a flush fluid; at least one of the fluids is viscosified with a degradable viscosifying agent. In other embodiments, at least one step (b) after the first step (b) is preceded by a step (a), or each step (b) is preceded by a step (a).

The total volume of the fluid injected in steps (c) preferably makes up less than 10 percent of the total volume of fluid injected in the treatment. In each cycle the ratio of the volume of fluid in stage C to the volume of fluid in stage B is preferably less than about 1/10.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates fracture system complexity, increasing from A to B to C.

FIG. 2 is a schematic of the manifold system.

FIG. 3 shows the pressure in the manifold system vs. time.

DETAILED DESCRIPTION OF THE INVENTION

The invention will be described in terms of the treatment of vertical wells, but is equally applicable to wells of any orientation. The invention will be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells. It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.

We have developed a method of increasing fracture system complexity to enhance hydrocarbon production from unconventional low-permeability reservoirs. In the method, a sequence of stages is pumped into the reservoir; a low viscosity fluid treatment is complemented by at least one stage of pumping of a relatively low volume of a fluid, viscosified by a degradable viscosifying agent that is used as a diverting agent. Pumping of the viscous fluid diverting agent leads to a net pressure increase and to plugging of some of the microfractures in the initial fracture system created, which induces formation of supplementary microfractures connected to the initial fracture network and increases the contact area with the formation rock. The injection of viscous slugs of diverting agent is generally repeated. Such a use of slugs of a viscous fluid enables stimulation of larger reservoir volumes in remote regions of a reservoir. After the treatment, the viscosified fluid degrades naturally or is destroyed with a breaker, opening up production from the temporarily-plugged fractures. Note that the present invention relates to a method of treatment redirection within an already stimulated zone which results in creation of a larger contact area with the reservoir because of a fracture complexity increase within that zone.

When multiple productive zones are fracture stimulated it is often necessary to treat multiple zones in multiple stages. This creates a need for a diverting technique which enables treatment redirection from zone to zone. Such diversion, optionally with new perforations shot after each treatment, is done, for example, with bridge plugs, ball sealers, solid gel plugs, or plugs of degradable fibers, powder, flakes, granules, pellets, and chunks, optionally with slowly water-soluble coatings. The other situation in which diversion is required is treatment redirection within a stimulating zone. In this case an additional formation rock volume is stimulated using the same entry point in the formation without treatment redirection to another zone along the wellbore. Interestingly, techniques have been developed using slugs of viscous fluids or fine sand for control of leak-off and for fracture complexity decrease, not increase, in naturally fractured reservoirs. Creation of a single fracture plane in the near-wellbore zone instead of multiple interconnected fracture channels has in the past been sought deliberately to provide a significant tortuosity decrease and minimize the risk of premature screen-out.

Slickwater treatments have been shown to provide production comparable to that from conventional gel treatments, but for significantly lower cost. One of the most important features of slickwater jobs is low gel damage, due to the low polymer content of the fluid. However, the low fluid viscosity strongly affects its proppant transport properties, and placement of proppant deep into a fracture is a challenge. Utilization of lightweight and ultra lightweight proppants has been one solution. Another solution is pumping a combination of slickwater and gel in stages with varying quantities of proppants; such treatments are often referred as hybrid fracs or hybrid water fracs. Although the objective of hybrid fracs is better proppant placement with a fluid of higher viscosity than that of slickwater, other benefits have been noted including creation of wider fractures and thus avoidance of proppant bridging. It has also been noted that hybrid fracs can generate longer effective frac lengths, but the effective conductivities in the hybrid fracs were not consistently higher than those in water fracs.

Slickwater fracs with no proppant or with coarse proppant only, or with alternation of these two, have been tried. However, the usual slickwater treatment includes the following stages: a) slickwater pad; b) slickwater stage with fine proppant (for example approximately 100-mesh sand (grains of from about 0.105 to about 0.21 mm) or about 30/70 sand (about 0.21 to about 0.595 mm)) in concentrations gradually increasing from about 0.1 to about 2 ppa (pounds proppant added) (about 0.012 to about 0.240 kg of sand added per liter of clean fluid); c) linear gel (with a typical viscosity of from about 10 to about 100 mPa·s at a shear rate of 100 s⁻¹) with coarse proppant (for example approximately 20/40 sand (about 0.42 to about 0.841 mm) or about 20/40 resin coated sand) in concentrations increasing to up to about 5 ppa (about 0.6 kg of sand added per liter of clean fluid) to prop open the near wellbore region of the fracture; and d) flush. Typically, the pad stage is from about 500 to about 3000 bbl (about 80 to about 480 m³), the slickwater stage is from about 500 to about 25,000 bbl (about 80 to about 4000 m³), the gel stage is from about 500 to about 25,000 bbl (about 80 to about 4000 m³) and the flush is approximately the volume of the wellbore from the wellhead to the perforations, sometimes plus up to about 50 bbl (about 8 m³).

The hybrid treatments attempt to achieve the benefits of both conventional gel and slickwater treatments. Typically hybrid fracs include pumping of: a) slickwater pad; b) an optional slickwater stage with fine proppant (for example less than about 0.5 ppa (about 0.06 kg/l of clean fluid)); c) cross-linked gel with a viscosity of about 100 to about 1000 mPa·s at a shear rate of 100 s⁻¹ with coarse proppant, for example about 20/40 (about 0.4 to about 0.841 mm), (at a concentration for example of up to about 5 ppa (about 0.6 kg of sand added per liter of clean fluid)); optionally repeating stages b) and c); and flush. Volumes are typically about the same as for the conventional slickwater treatments described above. In a modification of the hybrid frac called a reverse hybrid frac the sequence of fluid injection is changed, so a high viscosity polymer (linear or cross-linked) is used to create a fracture, while the proppant, transported with a low viscosity fluid, is pumped behind the viscous pad. The viscosity contrast results in the formation of fingers of low viscosity proppant laden fluid in the higher viscosity fluid and proppant settling is hindered by the layers (fingers) of the more viscous fluid. Again, as in the classical hybrid fracs, the objective of the design is to deliver proppant deeper into the fracture to ensure longer propped length and higher fracture conductivity. In any slickwater pumping schedule, when the fluid is switched from slickwater to viscous proppant slurry, the fluid may be changed from slickwater to viscous fluid for a period before proppant is added; for example in another version of a hybrid frac, slickwater is pumped first to generate length; this is then followed by a crosslinked gel pad, and then by coarse sand in a crosslinked gel.

The key distinction of the method of the present invention from the hybrid fracs is in the volumes of viscosified fluids pumped in the slickwater stages. Since proppant placement is not the real objective of the method of the invention, viscous fluid is only a small fraction of the total job volume. Furthermore, proppant concentration in the viscosified fluid is similar to that in slickwater stages.

Unconventional gas reservoirs are characterized by extremely low formation permeabilities (for example less than about 0.1 mD down to about 100 nD in shales), and stimulation treatments often require large treatment volumes (for example over about 15,000 m³ (1 Mgal)) and high pumping rates (as examples, at least about 6.4 m³/min (40 bpm), typically about 10 m³/min (60 bpm), and sometimes up to about 20 m³/min (120 bpm)) to open long fractures and generate complex fracture networks, which can provide unrestricted gas flow towards a wellbore. The fractures typically are propped with sands of various sizes transported by slickwater fluids, which are usually water with small amounts of polymeric friction reducers, having viscosities up to about 50 mPa·s at a shear rate of 100 s⁻¹. Fluids having higher viscosities, for example above about 15 cP would typically be called water frac fluids. Lightweight proppants, for example having specific gravities of from about 2.2 to about 2.8, and ultra lightweight proppants for example having specific gravities of from about 1.0 to about 2.0 may be used for water fracs. Slickwater fluids contain significantly lower polymer concentrations than linear or cross-linked gels, so they do much less damage to the proppant pack.

Various diversion techniques are used to increase the effective stimulated volume (ESV) of a reservoir. The methods rely on temporary plugging of some zones (for example already-stimulated zones) in order to stimulate others with the same treatment. Most of the existing diversion methods target welibores and perforations to stimulate different formation zones. These methods include various casing-conveyed zonal isolation tools, such as bridge plugs, sand plugs, ball sealers, induced stress diversion and others. Diversion within a fracture is less common in the art of hydraulic fracturing. One method provides near-wellbore fracture diversion on demand. The method uses a mixture of proppant and degradable fiber and a placement strategy to plug a fracture face temporarily in the near wellbore region to enable treatment diversion to a different wellbore zone.

The present invention discloses a method of fracture network complexity increase and reservoir contact area enhancement by means of viscosified fluids. The viscosified fluids may be selected from fluids such as, but not limited to, viscoelastic surfactants, borate and/or metal cross-linked polysaccharides, for example guar gums, cellulose derivatives, xanthans, scleroglucans, etc. The fluids may further include crosslink delay agents to control the fluid viscosity, breakers, including encapsulated breakers, to ensure slug degradation after the treatment, degradable fibers and other additives. Such fluids and their components are known to those skilled in the art. The method is preferably applied to formations having a permeability less than about 1 mD, and more preferably to formations having a permeability less than about 10 mD, and most preferably to shale formations with permeabilities less than 1000 nD. The method may be used in a refracturing treatment.

As in a common slickwater treatment, a typical treatment of the invention starts with a pad, stage A, in which a pure slickwater fluid is pumped. The pad stage creates the fracture system and ensures that the width is sufficient for proppant passage. The pad stage is followed by a large-volume stage B, pumping of a proppant-laden slickwater, which delivers the proppant into the opened main fracture and additional fracture networks. Fluid B makes up at least 75 percent of the total fluid volume of the treatment. The fluids of stages A and B have viscosities of less than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, preferably from about 1 to about 10 mPa·s at a shear rate of 100 s⁻¹. Fluids A and B may be the same or different. The proppants for slickwater treatments are known to those skilled in the art; non-limiting examples include sands and other rocks and minerals, including muscovite mica, ceramics, polymeric materials, biomaterials and mixtures of these materials. Special attention should be paid to the choice of proppant material, as slickwaters have quite poor transport properties due to their very low viscosities. A diversion stage C follows the far-field placement of proppant in stage B and involves pumping of a viscosified fluid, which may optionally further contain proppant and/or fiber material(s). The fluid of stage C has a viscosity, after viscosifying, greater than about 50 mPa·s, preferably from about 100 to about 1000 mPa·s, at a shear rate of 100 s⁻¹ under ambient conditions. Optionally, the fluid of stage C may be pumped as a low viscosity fluid and the viscosity of the fluid is increased in the reservoir; in that case, the initial viscosity is greater than about 20 mPa·s at a shear rate 100 s⁻¹ (with a preferred range of from about 20 to about 100 mPa·s at a shear rate of 100 s⁻¹) and the final viscosity is greater than about 50 mPa·s, preferably from about 100 to about 1000 mPa·s, at a shear rate of 100 s⁻¹ under ambient conditions. The volume of stage C is generally smaller than the volumes of the other stages of the treatment. The ratio of the volumes of fluid in stage C to fluid in stage B is less than about 1/10, preferably from about 1/100 to about 1/10. The upper limit of the total volume of fluid in stage C of each treatment cycle (before treatment redirection to another wellbore interval) is about 64 m³ (400 bbl); as little as about 10 m³ of fluid may be used. Fluid C optionally contains a fiber, for example a degradable fiber, and/or a proppant. The preferred proppant size is from about 0.05 mm to about 1 mm (preferably from about 0.2 to about 0.4 mm; the preferred proppant concentration is from about 0.012 to about 0.6 kg added per liter of clean fluid (most preferably from about 0.024 to about 0.24 kg per liter of clean fluid).

A particularly suitable method of pumping a low viscosity fluid Stage C and then having the viscosity of the fluid increase in a carbonate-containing reservoir, for example a carbonate-containing shale, is the use of an acidic fluid that undergoes an increase in viscosity when the pH is raised, for example by contact with the reservoir rock. Many such systems are known for use in acidizing and acid fracturing; they are commonly called self-diverting acids and when based on viscoelastic surfactants they are called viscoelastic diverting acids. In the present invention, they are used to divert slickwater. Examples are those based on viscoelastic surfactants, for example certain betaines. Suitable viscosifiers and systems are described in U.S. Pat. Nos. 6,399,546; 6,667,280; 6,903,054; 7,119,050; 7,148,184; 7,380,602; and 7,666,821. In addition to diversion, the use of such self-diverting acids in the present invention can further enhance the complexity of fracture networks by introducing heterogeneity by etching the formation and reducing the fracture initiation pressure, and also by selective dissolution of scales, that have usually accumulated in the natural fractures/fissures/fabric of a reservoir.

Stage C may also contain fibers, preferably having a diameter of from about 1 to about 100 microns (more preferably from about 10 to about 30 microns) and a length of from about 1 to about 50 mm (preferably from about 3 to about 35 mm) at a concentration of from about 0 to about 60 g per liter of clean fluid, (preferably about 1.2 to about 16 g per liter of clean fluid).

Substantially proppant free fluid is defined here as a fluid having a loading of proppant less than about 0.024 kg per liter of clean fluid. The viscous fluid is intended and therefore designed to divert, not to carry proppant or fiber. Stage C fluids are substantially proppant free.

Pumping of the viscosified fluid increases the net pressure in the fracture, which temporarily decreases fluid flow in a portion of the primary fracture and induces the formation of side fractures along the primary fracture. This temporary pressure increase can also reversibly increase the fracture width, decreasing the probability of proppant bridging in the fracture. As the viscosified fluid has a density close to that of the slickwater itself, the fluid slugs can be transported into a fracture network system without any of the problems associated with slug settling (see Example 1).

Fluids A and B are preferably selected from fresh water, brine, seawater, solutions of polymers, solutions of viscoelastic surfactants, gelled oils, viscosified diesel fuels, emulsions and mixtures of such fluids. Fluid C is preferably chosen from solutions of polymers, gels, cross-linked gels, solutions of viscoelastic surfactants, gelled oils, viscosified diesel fuels, and emulsions. These viscosifiers are preferably degradable. Preferred polymers include guar gum, gum arabic, gum karaya, tamarind gum, locust bean gum, cellulose, xanthan, scleroglucan, polyacrylamide, polyacrylate, combinations of these materials, and modified, substituted or derivatized versions of these polymers. The polymers in the fluids may be crosslinked, for example by compounds of boron, aluminum, titanium, zirconium, chromium, iron, copper, zinc, antimony, organic or inorganic polyions and combination of these materials. The fluids may optionally contain crosslink delay agents or gel or polymer breakers, for example encapsulated gel breakers, internal delayed gel breakers, temperature-activated gel breakers and combination of these. The proppant in fluid B, and optionally in fluid C, preferably is selected from sands, ceramics, glasses, rocks and minerals such as mica, organic and inorganic polymers, metals and alloys, composite materials and mixtures of these materials. These proppants preferably have shapes selected from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs, fibers, meshes, arches/cells, meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and mixtures of these shapes. “Arches/cells” and “meshes/cells” are special three-dimensional organizations of materials, for example reticulated foamed polyurethane. Such materials have a three-dimensional bubble structure consisting, for example, of dodecahedrons, each face of which is a pentagon. The pentagons are formed by edges between which there is a membrane or window. At least one membrane is always missing, thus forming an open pore structure. Viscosifiers and proppants and methods of preparing these fluids are all known in the art.

The proppant in fluids B, and optionally C, preferably is in a size range of from about 5 to about 1000 microns, most preferably from about 50 to about 840 microns. These proppants may optionally be coated or may have an organophilic treatment. Fluid B preferably carries at least about 90 weight percent of the proppant in stages B and C.

The fluids of stages B and C may optionally also contain degradable materials, for example fibers, plates, flakes, beads and combinations of these materials. The degradable materials are chosen, for example, from polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of these materials.

Any of the fluids, in particular the fluids used in stages C, may be foamed or energized.

The fracture systems formed with water fracs in heterogeneous reservoirs are often believed to have complex and branched structures with many intersecting natural fractures, with changes in fracture direction (see FIG. 1C). However, the viscosified fluids and methods used in the present invention plug the existing fractures at a considerable distance from the wellbore; this depends on fluid viscosity which in turn may be controlled by a delay agent. By varying the delay time, an operator can control the distance from the wellbore at which the plugging occurs. The plug formed drastically increases the pressure and induces creation of new fractures connected to the same fracture network, growing in other directions, stimulating previously non-treated zones (see Example 2).

Stages A (optionally) and B are repeated after each diversion (stage C) to create new fracture(s) and fracture networks. Each pumping of at least a stage B and a stage C (in either order) is called a cycle; each cycle contains at least stages B and C; the entire treatment starts with a stage A. The cycles, for example ABC-ABC (preferred), ABC-BC, ABC-BC-BC, ACB-CB-CB, ABC-BAC-BC, or ABC-BC-ABC-BC, etc., are repeated as many times as necessary to develop the fracture network desired. The ratio of the volumes, in any cycle, of fluid in stage C to fluid in stage B is less than about 1/10, preferably from about 1/100 to about 1/10. The upper limit of the total volume of fluid in stage C of each treatment cycle (before treatment redirection to another wellbore interval) is about 64 m³ (400 bbl); as little as about 10 m³ of fluid may be used. Any cycle may optionally include a stage A and optionally may be followed by a stage D, in which a gel with coarse (for example from about 0.4 to about 1 mm (preferably from about 0.42 to about 0.84 mm)) proppant is pumped to prop the primary fracture and to ensure that it has a high conductivity. Any stage D is optionally followed with a stage E, pumping of a proppant flowback control agent, e.g. resin-coated proppant or any other proppant control agent known from the art, such as fibers, and finally with an optional flush, stage F. Water, brine, or a fluid that is the same as or similar to the fluid of any stage A may be used for the flush; the flush is usually about the volume of the wellbore from the wellhead to the top or bottom of the perforated interval being treated (increased or decreased by from about 3 to about 100 bbl (about 18 to about 65 m³). The fluid of any stage D has a viscosity of about 1 to about 1000 mPa·s at a shear rate of 100 s⁻¹; the fluid of any stage E has a viscosity of about 1 to about 50 mPa·s at a shear rate of 100 s⁻¹.

The fluid of each stage A, stage B, stage C, stage D, or stage E need not be identical to the fluid of any other stage A, stage B, stage C, stage D, or stage E. After the end of the treatment and fracture closure, the fluid plugs created by stage(s) C for diversion degrade naturally or are destroyed with oxidative or other types of breakers, which reduce the fluid viscosity. This opens the originally fractured regions of the reservoir and provides hydrocarbon or other fluid transport to the wellbore, enhancing production.

The examples below illustrate the transportability of a viscosified fluid in a slickwater fluid having a similar density (Example 1); plugging of a manifold system (which simulates a complex fracture network) with a slug of viscosified fluid (Example 2); and degradation of the plug over time in the presence of an oxidative breaker (Example 3). The examples are presented for the purpose of illustrating the preferred embodiments of the invention and do not constitute any limitations to the scope of the invention.

Example 1

A fluid slug prepared from a borate cross-linked guar gel, having a guar concentration of 6 g/L (50 lb/1000 gal) was placed in a Plexiglas settling slot with dimensions 1000×300×4 mm, above a slug of similar-density slickwater containing 0.05 weight percent of a polyacrylamide friction reducer. No slug diffusion during the experimental time of 4 hours at room temperature was observed. The viscous slug remained consolidated and floated on the slickwater slug without settling.

Example 2

The behavior of a viscous slug being transported in a long horizontal pipe was studied. A laminar fluid flow regime was tested. These data can be used to evaluate slug transport inside a fracture. In order to investigate slug transport dependencies, a special set-up was constructed. It consisted of a clear plastic water pipe (35 m in length and 18 mm ID), systems for injection of the viscous slug and of a base fluid, a water pump, and two photo sensors (one at the beginning and one at the end of the pipe) to determine the length of the viscous slug, and a data acquisition system. A special loop was used for injection of slugs of the viscous fluid. A viscous slug of a desired composition was loaded into the slug injection loop before the experiment and was isolated from the main line by valves. Base fluid was pumped through the pipe for several minutes until the base fluid flow stabilized. Once flow stabilization was attained, the flow was directed into the slug sample injection loop and a viscous slug was pumped into the system.

Viscous fluid slugs were prepared from a borate cross-linked guar gel having a guar concentration of 6 g/L (50 lb/1000 gal) and dyed with phenolphthalein for visualization; a base fluid, slickwater, containing 0.05 wt % of a polyacrylamide friction reducer was used. The slickwater and viscous fluid slugs were pumped and slug stretching during transport inside the tube was studied. The flow rate of the slickwater was 8.1 L/min, which corresponds to a linear velocity of 43.6 cm/sec. The experiment showed that the average viscous fluid slug velocities were 42 cm/sec. The difference between the base fluid and the viscous slug velocities was caused by a fingering effect in which the denser and more viscous fluid was transported with a lower rate relative to the base fluid velocity. The initial slug lengths injected were 215±20 cm. The final slug lengths at the end of the tube were 250±24 cm. No significant slug stretching during transportation inside the tube was observed when the flow was laminar. This experiments shows that it is possible to transport slugs of viscous fluids inside a fracture; the slugs were not significantly dispersed under conditions that mimic the flow conditions inside a fracture.

Example 3

A manifold [3] as shown in FIG. 2 was built using Swagelok tubes with outer diameters varying from 6.35 mm (0.25 in) down to 1.59 mm ( 1/16 in). FIG. 3 shows the test results in which the pressure inside the tube was plotted against time. The same slickwater as used in Examples 1 and 2 was pumped through the manifold with a Knauer pump [1] at 0.5 l/min flow rate with pressures generally not exceeding 138 kPa (20 psi). Slugs of the crosslinked gel used in Examples 1 and 2 were then placed in the slurry tank [2] and the pressure was followed during pumping; the pressure increased up to 1007 kPa (146 psi), at which pressure the pressure relief rapture disk [4] broke. The manifold system emulates a complex fracture network during the diversion stage, and the rupture disk break mimics fracturing of a non-stimulated zone of the reservoir due to the net pressure increase. 

Having thus described our invention, we claim:
 1. A method for fracturing a subterranean formation comprising a first cycle comprising (a) injecting a pad fluid having a viscosity of less than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, (b) injecting proppant slurry having a viscosity of less than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, (c) injecting a thickened fluid having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions, and one or more than one subsequent cycles comprising repeating steps (b) and (c).
 2. The method of claim 1 wherein the pad fluid is injected first.
 3. The method of claim 1 wherein the thickened fluid has a viscosity of less than about 20 mPa·s as pumped and then thickens.
 4. The method of claim 3 wherein the reservoir contains carbonate and the thickened fluid is initially acidic.
 5. The method of claim 1 wherein the thickened fluid further comprises proppant.
 6. The method of claim 1 wherein the total volume of the fluid injected in steps (b) comprises at least 75 percent of the total volume of fluid injected in the treatment.
 7. The method of claim 1 wherein the fluid injected in steps (b) carries at least 90 percent of the total proppant injected in the treatment.
 8. The method of claim 1 wherein the permeability of the formation is less than about 1 mD.
 9. The method of claim 1 wherein the proppant has a shape selected from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs, fibers, arches/cells, meshes, meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and mixtures of these shapes.
 10. The method of claim 1 wherein the size of the proppant ranges from about 5 to about 1000 microns.
 11. The method of claim 1 wherein at least one of the injected fluids comprises solid degradable materials.
 12. The method of claim 11 wherein the degradable materials comprise polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures thereof.
 13. The method of claim 11 wherein the degradable materials are used in the form of fibers, plates, flakes, beads and combinations thereof.
 14. The method of claim 1 wherein the fluid of step (a) or the fluid of step (b) or both comprise a friction reducing agent.
 15. The method of claim 1 wherein the fluid of step or steps (c) comprises less than about 0.024 kg proppant per liter of clean fluid.
 16. The method of claim 1 wherein the fluid of step or steps (c) is substantially proppant free.
 17. The method of claim 1 wherein one or more than one cycle is followed by injection of a fluid having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions comprising a coarse proppant.
 18. The method of claim 17 wherein the one or more steps of injection of a fluid having a viscosity of greater than about 50 mPa·s at a shear rate of 100 s⁻¹ under ambient conditions comprising a coarse proppant is followed by injection of a fluid comprising a proppant flowback control agent.
 19. The method of claim 1 comprising a final step of injecting a flush fluid.
 20. The method of claim 1 wherein at least one of the fluids is viscosified with a degradable viscosifying agent.
 21. The method of claim 1 wherein at least one step (b) after the first step (b) is preceded by a step (a).
 22. The method of claim 1 wherein each step (b) is preceded by a step (a).
 23. The method of claim 1 wherein the total volume of the fluid injected in steps (c) comprises less than 10 percent of the total volume of fluid injected in the treatment.
 24. The method of claim 1 wherein in each cycle the ratio of the volume of fluid in stage C to the volume of fluid in stage B is less than about 1/10. 